Burst QAM downhole telemetry system

ABSTRACT

A downhole telemetry system that transmits a burst-QAM uplink signal to the surface of the well is disclosed. In a preferred embodiment, the well includes composite tubing having circumferentially-spaced electrical conductors helically wound within the walls of the tubing. A downhole instrument coupled to a pair of adjacent conductors transmits a burst-QAM uplink signal to a surface system similarly coupled to the pair of adjacent conductors. The burst-QAM signal preferably comprises a series of data frames carrying telemetry data. Each data frame is preferably preceded by a quiet interval (when no signal is present), a timing synchronization sequence, and a training sequence. The timing synchronization sequence is designed for easy timing recovery at the surface, and the training sequence is designed to aid the adaptation of the equalizer. The data frame itself preferably includes a synchronization field, a data count, and a checksum in addition to the data. Direct digital synthesis is preferably employed to modulate the uplink signal.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to a telemetry system for transmittingdata from a downhole drilling assembly to the surface of a well. Moreparticularly, the present invention relates to a system and method forsignaling over information conduits coupled between a downholetransmitter and an uphole receiver.

2. Description of the Related Art

Modern petroleum drilling and production operations demand a greatquantity of information relating to parameters and conditions downhole.Such information typically includes characteristics of the earthformations traversed by the wellbore, along with data relating to thesize and configuration of the borehole itself. The collection ofinformation relating to conditions downhole, which commonly is referredto as “logging”, can be performed by several methods.

In conventional oil well wireline logging, a probe or “sonde” housingformation sensors is lowered into the borehole after some or all of thewell has been drilled, and is used to determine certain characteristicsof the formations traversed by the borehole. The upper end of the sondeis attached to a conductive wireline that suspends the sonde in theborehole. Power is transmitted to the sensors and instrumentation in thesonde through the conductive wireline. Similarly, the instrumentation inthe sonde communicates information to the surface by electrical signalstransmitted through the wireline.

The problem with obtaining downhole measurements via wireline is thatthe drilling assembly must be removed or “tripped” from the drilledborehole before the desired borehole information can be obtained. Thiscan be both time-consuming and extremely costly, especially insituations where a substantial portion of the well has been drilled. Inthis situation, thousands of feet of tubing may need to be removed andstacked on the platform (if offshore). Typically, drilling rigs arerented by the day at a substantial cost. Consequently, the cost ofdrilling a well is directly proportional to the time required tocomplete the drilling process. Removing thousands of feet of tubing toinsert a wireline logging tool can be an expensive proposition.

As a result, there has been an increased emphasis on the collection ofdata during the drilling process. Collecting and processing data duringthe drilling process eliminates the necessity of removing or trippingthe drilling assembly to insert a wireline logging tool. It consequentlyallows the driller to make accurate modifications or corrections asneeded to optimize performance while minimizing down time. Designs formeasuring conditions downhole including the movement and location of thedrilling assembly contemporaneously with the drilling of the well havecome to be known as “measurement-while-drilling” techniques, or “MWD”.Similar techniques, concentrating more on the measurement of formationparameters, commonly have been referred to as “logging while drilling”techniques, or “LWD”. While distinctions between MWD and LWD may exist,the terms MWD and LWD often are used interchangeably. For the purposesof this disclosure, the term MWD will be used with the understandingthat this term encompasses both the collection of formation parametersand the collection of information relating to the movement and positionof the drilling assembly.

When oil wells or other boreholes are being drilled, it is frequentlynecessary or desirable to determine the direction and inclination of thedrill bit and downhole motor so that the assembly can be steered in thecorrect direction. Additionally, information may be required concerningthe nature of the strata being drilled, such as the formation'sresistivity, porosity, density and its measure of gamma radiation. It isalso frequently desirable to know other downhole parameters, such as thetemperature and the pressure at the base of the borehole, for example.Once this data is gathered at the bottom of the borehole, it istypically transmitted to the surface for use and analysis by thedriller.

Sensors or transducers typically are located at the lower end of thedrill string in LWD systems. While drilling is in progress these sensorscontinuously or intermittently monitor predetermined drilling parametersand formation data and transmit the information to a surface detector bysome form of telemetry. Typically, the downhole sensors employed in MWDapplications are positioned in a cylindrical drill collar that ispositioned close to the drill bit. The MWD system then employs a systemof telemetry in which the data acquired by the sensors is transmitted toa receiver located on the surface. There are a number of telemetrysystems in the prior art which seek to transmit information regardingdownhole parameters up to the surface without requiring the use of awireline tool. Of these, the mud pulse system is one of the most widelyused telemetry systems for MWD applications.

The mud pulse system of telemetry creates “acoustic” pressure signals inthe drilling fluid that is circulated under pressure through the drillstring during drilling operations. The information that is acquired bythe downhole sensors is transmitted by suitably timing the formation ofpressure pulses in the mud stream. The information is received anddecoded by a pressure transducer and computer at the surface.

In a mud pressure pulse system, the drilling mud pressure in the drillstring is modulated by means of a valve and control mechanism, generallytermed a pulser or mud pulser. The pulser is usually mounted in aspecially adapted drill collar positioned above the drill bit. Thegenerated pressure pulse travels up the mud column inside the drillstring at the velocity of sound in the mud. Depending on the type ofdrilling fluid used, the velocity may vary between approximately 3000and 5000 feet per second. The rate of transmission of data, however, isrelatively slow due to pulse spreading, distortion, attenuation,modulation rate limitations, and other disruptive forces, such as theambient noise in the drill string. A typical pulse rate is on the orderof a pulse per second (1 Hz).

Given the recent developments in sensing and steering technologiesavailable to the driller, the amount of data that can be conveyed to thesurface in a timely manner at 1 bit per second is sorely inadequate. Asone method for increasing the rate of transmission of data, it has beenproposed to transmit the data using vibrations in the tubing wall of thedrill string rather than depending on pressure pulses in the drillingfluid. However, the presence of existing vibrations in the drill stringdue to the drilling process severely hinders the detection of signalstransmitted in this manner.

SUMMARY OF THE INVENTION

Accordingly, there is disclosed herein a downhole telemetry system thattransmits a burst-QAM uplink signal to the surface of the well. In apreferred embodiment, the well includes composite tubing havingcircumferentially-spaced electrical conductors helically wound withinthe walls of the tubing. A downhole instrument coupled to a pair ofadjacent conductors transmits a burst-QAM uplink signal to a surfacesystem similarly coupled to the pair of adjacent conductors. Theburst-QAM signal preferably comprises a series of data frames carryingtelemetry data. Each data frame is preferably preceded by a quietinterval (when no signal is present), a timing synchronization sequence,and a training sequence. The timing synchronization sequence is designedfor easy timing recovery at the surface, and the training sequence isdesigned to aid the adaptation of the equalizer. The data frame itselfpreferably includes a synchronization field, a data count, and achecksum in addition to the data. Direct digital synthesis is preferablyemployed to modulate the uplink signal.

BRIEF DESCRIPTION OF THE DRAWINGS

A better understanding of the present invention can be obtained when thefollowing detailed description of the preferred embodiment is consideredin conjunction with the following drawings, in which:

FIG. 1 is a schematic view of an oil well in which the telemetry systemmay be employed;

FIG. 2 is an isometric schematic of a composite tubing section havinghelically wound information conduits contained within;

FIG. 3 is a schematic of the circuits that couple the telemetry signalsto the tubing;

FIG. 4 is a functional block diagram of a surface computer system;

FIG. 5 is a functional block diagram of a downhole communications modulein the supervisory sub;

FIG. 6 is an exemplary implementation of an uplink telemetry data frame;

FIG. 7 is a functional block diagram of an uplink telemetry transmitter;and

FIG. 8 is a functional block diagram of an uplink telemetry receiver.

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and will herein be described in detail. Itshould be understood, however, that the drawings and detaileddescription thereto are not intended to limit the invention to theparticular form disclosed, but on the contrary, the intention is tocover all modifications, equivalents and alternatives falling within thespirit and scope of the present invention as defined by the appendedclaims.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

Turning now to the figures, FIG. 1 shows a well having a spool 102 ofcomposite tubing 104 being injected into a wellbore by an injector 106.The composite tubing 104 is injected through a packer 108 and a blowoutpreventer 110, and passes through casing 112 into the wellbore. In thewell, a downhole instrument 114 is coupled to the composite tubing 104and configured to communicate to a surface computer system 116 viainformation conduits embedded contained in the composite tubing 104. Apower supply 118 may be provided to supply power to downhole instrument114 via power conduits in composite tubing 104.

Surface computer system 116 is configured to communicate with downholeinstrument 114. Downhole instrument 114 may, for example, be asupervisory sub for a bottom-hole drilling assembly. The sub may becoupled to downhole sensors and/or control devices configurable tomeasure and set, respectively, downhole parameters. Examples of sensorsinclude temperature, pressure, density, and flow-rate sensors. Examplesof control devices include valves, variable-aperture ports, heaters, andartificial lift devices.

Surface computer system 116 is preferably configured by software 120 tomonitor and control downhole instrument 114. System 116 may include adisplay device 122 and a user-input device 124 to allow a human operatorto interact with the system control software 120.

An isometric representation of composite tubing 104 is shown in FIG. 2.As the name suggests, composite tubing 104 is a tube having walls 202made primarily of a composite material such as, e.g. fiberglass orcarbon fiber, although other suitable materials are known andcontemplated. Conduits 204 may be embedded in the walls of compositetubing. To reduce the probability of conduit breakage, the conduits arepreferably wound helically around the tubing bore within the walls ofthe composite tubing. The winding angle is preferably a function of thestress coefficient differential between the conduit material and thecomposite material.

In a preferred embodiment, the conduits 204 contained in the compositetubing are electrical conductors, although one or more of the conduitsmay alternatively be optical fibers or hydraulic conduits. Preferably,six circumferentially-spaced conductors are provided, with two adjacentconductors dedicated to carrying telemetry signals.

FIG. 3 shows one circuit configuration which allows the uplink telemetrysignal to share electrical conductors with the downlink telemetrysignal. In the downhole portion of the coupling circuit configuration,an isolation transformer 302 preferably couples the telemetry signalconductors of the tubing to the downhole instrument. A center-tappedsecondary winding has one terminal end coupled to a high pass filter(HPF) 304 via a transmit resistance R_(T), and the other terminal endcoupled to a low pass filter (LPF) 306 with a shunt resistance R_(R) toground. The center tap is coupled to ground via an impedance block 308for impedance matching purposes.

HPF 304 blocks signals below the uplink signal cutoff frequency, therebypreventing any uplink signal energy from interfering with the downlinksignal. The uplink signal energy is screened off from the downlinksignal by LPF 306, which blocks any signal energy above the cutofffrequency of the downlink signal.

It is noted that the energy of the uplink and downlink signals isexpected to be comparable downhole. This is not the case at the surface,where the downlink signal energy is expected to be substantially greaterthan the uplink signal energy. To prevent the downlink signal fromoverwhelming the uplink signal detectors, a bridge arrangement is usedin the uphole portion of the coupling circuit configuration.

The surface portion of the coupling circuit configuration preferablyuses an isolation transformer 310 to couple to the telemetry signalconductors of the tubing. One terminal of the secondary winding iscoupled to ground, while the other terminal is coupled to a transmitsignal node 312 via a resistance R. A matching impedance 314 also hasone terminal coupled to ground and the other terminal coupled to node312 via a second, identical resistance R. The downlink signal isprovided to node 312 via a low pass filter 316 and a power amplifier318. The downlink signal voltage on node 312 causes similar currents toflow in the two branches, with a small difference caused by the uplinksignal. This uplink signal difference can be detected in the form of avoltage difference between the intermediate nodes of the branches. Adifferential amplifier 320 amplifies this difference and provides it toa high pass filter 322 for filtering. The discrimination of the highpass filter 322 in filtering out the downlink signal is aided by thecommon mode rejection of the differential amplifier.

Although a specific coupling circuit configuration has been described,it is recognized that other coupling techniques may be used. Othersuitable “4-wire to 2-wire” coupling configurations are known in the artand may be used. Alternatively, the uplink and downlink signals may becarried on separate sets of conductors, or may be transformed intooptical signals or pressure signals for other conduit types.

FIG. 4 shows one embodiment of surface computer system 116. System 116includes a central processing unit 402 coupled to a system memory 404via a bridge 406. System memory 404 stores software 408 for execution byprocessor 402. Bridge 406 also couples processor 402 to a peripheral bus410. Peripheral bus 410 supports the transfer of data to and from theprocessor 402. Peripheral devices connected to peripheral bus 410 canthereby provide the processor 402 with access to the outside world. Inthe shown embodiment, a signal conditioning board 412 and a digitaldecoder board 414 are coupled to the peripheral bus 410.

Signal conditioning board 412 is also coupled to the telemetry conduitsof tubing 104. Downlink data that the processor 402 wishes to send tothe downhole instrument 114 is provided to bus interface logic 422 ofthe signal conditioning board 412. The interface logic 422 handlescompliance with the bus protocol and extracts the downlink data from thebus signals to be provided to frequency-shift key (FSK) modulator 424.FSK modulator 424 converts the data into an analog downlink signal whichis then provided to LPF 316 to screen out any high frequency components.Isolation transformer 310 puts the downlink signal onto the telemetryconduits and extracts the uplink signal, passing it to HPF 322 whichscreens out any low frequency components. The uplink signal is amplifiedby amplifier 432 and provided to an analog-to-digital converter (ADC)442 on digital decoder card 414.

ADC 442 preferably provides the digitized signal to a digital signalprocessor (DSP) 444 for filtering and decoding. DSP 444 is configured bysoftware to perform bandpass or matched filtering 446 and equalizationand timing recovery 448 to extract the uplink data symbols. The datasymbols are decoded 450 and the decoded uplink data is provided toprocessor 402 for analysis. Details of the uplink telemetry signalformat and decoding will be discussed further below.

FIG. 5 shows one embodiment of the downhole instrument telemetry module.A DSP 502 is configured by software to format and encode 504 uplink datafor transmission to the surface. The encoded digital data is preferablymodulated in quadrature amplitude modulation (QAM) form by a directdigital synthesis (DDS) chip 506 to provide an analog uplink signal. Theanalog uplink signal is high pass filtered 304 and provided to isolationtransformer 302. Isolation transformer couples the uplink signal to thetelemetry conduits and couples the downlink signal from the telemetryconduits to low pass filter 306. LPF 306 screens out the signal energyabove the cutoff frequency, and a demodulator 508 converts the downlinksignal into digital baseband form for decoding by DSP 502.

In a preferred embodiment, the downlink signal is a FSK modulated signalusing the 2.4-9.6 kHz frequency band. This signal is preferably used totransmit commands and configuration parameters to the downholeinstrument. The uplink signal is preferably a burst-QAM modulated signalusing the 16-48 kHz frequency band. This signal is preferably used totransmit measurement data to the surface.

The DSP may optionally be a chip from the ADSP-2100 Family of DSPMicrocomputers manufactured and sold by Analog Devices, a company doingbusiness in Norwood, Mass. The DDS chip may optionally be an AD7008 CMOSDDS Modulator manufactured and sold by the same company.

It is noted that the uplink link preferably employs burst-QAM to achieveincreased channel capacity without a commensurate increase in receivercomplexity. In one embodiment, the burst-QAM communication is done inthe form of uplink data frames 602, each frame being preceded by a quietinterval 604 and a timing synchronization sequence 606, as shown in FIG.6. An equalization training sequence 608 may also be providedimmediately before the data frame 602. It is contemplated that theuplink communication be done in terms of 16-bit words, each of which aretransmitted as four 4-bit (16-QAM) symbols. The quiet interval 604 iscontemplated to be 30 words (120 symbol periods), the timing sequence606 is contemplated to be 20 words (80 symbols), the training sequence608 to be 126 words (504 symbols), and the frame 602 to be a maximum of1024 words (4096 symbols). It is recognized, however, that otherconfigurations may also be suitable. For example, other word lengths maybe employed, and the QAM constellation may be made larger (e.g. 32, 64,128, 256, 512, 1024, or more constellation points), or smaller (i.e. 2,4, or 8 constellation points).

Data frame 602 preferably begins with two synchronization words, a datacount word, up to 1020 words of data, and ends with a checksum word. Thedata count word preferably indicates the number of data words. Thenumber of data words per frame may be adjusted according to systemrequirements and according to a desired rate of recurrence of theresynchronization and re-training sequences. For example, if the numberof data words per frame is 1020 in the above described embodiment, thetiming resynchronization and retraining will occur over 10 times persecond. However, in some conditions it may be desired to increase theresynchronization frequency to over 20 times per second. This may beachieved by reducing the number of data words per frame to about 512.Alternatively, the number of bits per QAM symbol may be increased toreduce the number of symbols per frame.

FIG. 7 shows, in functional block form, the uplink signal transmit path700. In block 702 the data frame 602 is “scrambled” by bit-by-bitXOR-ing it with a pseudorandom sequence. The pseudorandom sequence is aneasily reproduced mask which “randomizes” the data frame to removepredictable, periodic patterns that often occur in measurement data.Such patterns, if not removed, may cause undesirable spectral lines thatinterfere with adaptive equalization in the receiver.

The scrambled data is then, in block 704, divided into symbols that aremapped to signal points in the QAM constellation. In block 706, thesymbols are modulated onto a carrier frequency, filtered and amplifiedin block 710, and coupled to the tubing telemetry conduits. A preamblegenerator block 708 is shown parallel to the data path. Preamblegenerator 708 generates the quiet period 604, timing synchronizationsequence 606, and training sequence 608, and inserts them into thetransmit signal ahead of each data frame. Referring momentarily to FIG.5, blocks 702 and 704 may be part of encoder software 504, blocks 706and 708 may be implemented by the DDS chip 506, and block 710 may beimplemented by HPF 304.

FIG. 8 shows, in functional block form, the uplink signal receive path800. In block 802, the signal received from the telemetry conduits isfiltered to screen out signal energy below the uplink signal cutofffrequency. The uplink signal is then digitized in block 804, andmatch-filtered in block 806 to maximize the signal-to-noise ratio. Inblock 808, a timing recovery algorithm operates to lock the receivertiming to the timing synchronization sequence. In block 810, the uplinksignal is equalized to correct for channel effects. During theequalization of the training sequence, knowledge of the trainingsequence is used to adapt the equalizer to the telemetry channel. Theequalizer consequently exhibits improved equalization performance on thedata frame. The equalizer output is a sequence of QAM symbols. In block812, the symbol sequence is converted to a 16-bit word sequence, withproper alignment achieved from knowledge of the training sequence. Block814 blocks the extraneous words from the quiet interval, the timingsequence, and the training sequence, and passes on only the data frame.In block 816, the scrambling operation is reversed, the check sumverified, and the data count, along with the data words, provided asoutput. Referring momentarily to FIG. 4, block 802 corresponds to block322, block 804 to block 442, block 806 to block 446, blocks 808 and 810to block 448, and blocks 812-816 to block 450.

The exemplary embodiments described above provide for telemetry throughconduits in composite tubing. In the case of electrical conductors, thecomposite tubing telemetry channel is expected to have a range of up to50,000 ft with an attenuation of 40-45 dB in the frequency ranges underconsideration. The framing structure employed in burst-QAM signaling isexpected to provide regularly recurring opportunities for timingresynchronization and equalizer retraining. This is expected tosignificantly improve the reliability of the uplink channel.

It is noted that the telemetry system disclosed herein may have multipleapplications, including, for example, smart wells. Smart wells areproduction wells that may have sensors and controllable mechanismsdownhole. The sensors may, for example, be used to detect density andflow rates. An uphole system may use this information to operate thecontrollable mechanisms (e.g. variable aperture ports and heaters orother artificial lift mechanisms) to optimize the production of thewell.

Numerous variations and modifications will become apparent to thoseskilled in the art once the above disclosure is fully appreciated. It isintended that the following claims be interpreted to embrace all suchvariations and modifications.

What is claimed is:
 1. A well comprising: composite tubing having atelemetry conduit; a surface system coupled to the telemetry conduit;and a downhole instrument coupled to the surface system via thetelemetry conduit, wherein the downhole instrument is configured totransmit telemetry information to the surface system using burstquadrature amplitude modulation (burst-QAM).
 2. The well of claim 1,wherein the burst-QAM uses a signal constellation of 16 points.
 3. Thewell of claim 1, wherein the composite tubing includes multiple,circumferentially-spaced conduits, and wherein of said multipleconduits, two adjacent ones are dedicated to information communicationbetween the surface system and the downhole instrument.
 4. The well ofclaim 3, wherein said multiple conduits are electrical conductors. 5.The well of claim 1, wherein the downhole instrument is configured totransmit the telemetry information in data frames, and wherein the dataframes are interspersed with quiet periods.
 6. The well of claim 1,wherein the downhole instrument is configured to transmit the telemetryinformation in data frames, and wherein each data frame is preceded by arespective timing synchronization sequence.
 7. The well of claim 1,wherein the downhole instrument is configured to transmit the telemetryinformation in data frames, and wherein each data frame is preceded by arespective training sequence.
 8. The well of claim 5, wherein each dataframe consists of a plurality of synchronization words, a data countfield, a plurality of data words, and a check word.
 9. The well of claim1, wherein the downhole instrument includes a transmit path having apreamble generator configured to transmit a preamble before each dataframe.
 10. The well of claim 9, wherein the transmit path includes adata scrambler configured to combine data frame data words with a maskto randomize the data words.
 11. The well of claim 10, wherein thetransmit path includes a direct digital synthesis modulator configuredto modulate the scrambled data words using quadrature amplitudemodulation.
 12. The well of claim 11, wherein the transmit path includesa high pass filter coupled between the direct digital synthesismodulator and an isolation transformer.
 13. The well of claim 10,wherein the surface system includes an uplink receive path having: atiming recovery module configured to generate a clock signal locked to atiming synchronization sequence preceding each data frame in thetelemetry signal; an adaptive equalizer configured to update filtercoefficients in response to a training sequence preceding each dataframe in the telemetry signal; a framing module configured to strip thetiming synchronization sequences and the training sequences from thetelemetry signal; and a descrambling module configured to combine thedata frames with the mask to reverse a downhole scrambling operation.14. The well of claim 13, wherein the timing synchronization sequencesand training sequences are repeated at least 10 times per second.